Acoustic illumination for flow-monitoring

ABSTRACT

Externally generated noise can be coupled into a fluid carrying structure such as a pipe, well, or borehole so as to artificially acoustically “illuminate” the pipe, well, or borehole, and allow fluid flow in the structure or structural integrity to be determined. In the disclosed system, externally generated noise is coupled into the structure being monitored at the same time as data logging required to undertake the monitoring is performed. This has three effects. First, the externally generated sound is coupled into the structure so as to “illuminate” acoustically the structure to allow data to be collected from which fluid flow may be determined, and secondly the amount of data that need be collected is reduced, as there is no need to log data when the structure is not being illuminated. Thirdly, there are signal processing advantages in having the data logging being undertaken only when the acoustic illumination occurs.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a Continuation of U.S. application Ser. No.14/440,138, filed May 1, 2015 which claims priority under 35. U.S.C. §371 to Patent Cooperation Treaty Application No. PCT/GB2013/052875,filed Nov. 1, 2013, which claims the benefit of earlier-filed BritishApplication No. GB 1219797.6, filed Nov. 2, 2012, the entire contents ofwhich are incorporated herein by reference.

TECHNICAL FIELD

The present invention relates to a method and system which makes use ofactive acoustic illumination of fluid carrying structures such asboreholes, wells, pipes, and the like to allow for fluid flow monitoringor structural integrity monitoring to occur.

BACKGROUND TO THE INVENTION AND PRIOR ART

Optical fibre based distributed acoustic sensors (DAS) are known in theart. One high performance example is the iDAS™, available from SilixaLimited, of Elstree, UK. Further details of the operation of a suitableDAS are given in WO2010/0136809 and WO2010/136810, which also disclosethat distributed acoustic sensors may be used for in-well applications,in that the acoustic noise profile can be used to measure the flow bynoise logging at every location along the well. In addition, the noisespectrum can be used to identify the phase of the fluid.

However, one problem that arises in the use of DAS for flow monitoringis in fluid carrying structures where the flow is quiet, for examplewhere the flow is substantially laminar, or with few eddies or otherturbulent regions that cause noise. In such a case acoustic monitoringof the fluid carrying structure is unable to determine the fluid flow,or the fluid phase, due to the lack of input information into thesensor. Moreover, in fluid carrying structures where the flow issometimes noisy and sometimes quiet, the monitoring of such structureswith a DAS can result in large amounts of data, much of which is oflittle use when no noise is present.

Examples of flow carrying structures that are sometimes too quiet forconventional DAS monitoring are oil wells with low flow rates, and shaleoil or shale gas wells. Even horizontal sections of piping can havequiet flow.

SUMMARY OF THE INVENTION

Embodiments of the present invention address the above problem by makinguse of a physical effect observed by the present applicants that noise,such as externally generated or internally generated noise, can becoupled into a fluid carrying structure such as a pipe, well, orborehole so as to artificially acoustically “illuminate” the pipe, well,or borehole, and allow fluid flow in the structure to be determined. Inparticular, in some embodiments of the invention acoustic energy iscoupled into the structure being monitored at the same time as datalogging required to undertake the monitoring is performed. The acousticenergy may have been deliberately created for the purpose of couplinginto the structure, or it may have been created for another purpose, forexample for seismic surveying, and is then also used for coupling intothe structure by way of convenience. Alternatively, the acoustic energymay be incident noise that has not been specifically created for anypurpose.

The coupling of acoustic energy into the structure has three effects, inthat firstly the acoustic energy is coupled into the structure so as to“illuminate” acoustically the structure to allow data to be collectedfrom which fluid flow or structural integrity may be determined, andsecondly the amount of data that need be collected is reduced, as thereis no need to log data when the structure is not being illuminated.Thirdly, there are signal processing advantages in having the datalogging being undertaken only when the acoustic illumination occurs, inthat any data averaging that needs to be performed is taken only overthe (usually short) period of illumination. This can increase the signalto noise ratio considerably.

In view of the above, from one aspect there is provided a method ofmonitoring a fluid-flow carrying structure. The method comprisesdetermining the generation of an acoustic wave; and at the same time asthe generated acoustic wave is incident on the structure, sensing, usinga distributed acoustic sensor, acoustic energy coupled into thefluid-flow carrying structure from the incident generated acoustic wave.Acoustic data corresponding to the sensed acoustic energy may then bestored, at least temporarily.

With the above, a “quiet” flow carrying structure may be deliberatelyilluminated by the generated acoustic wave, and acoustic data resultingfrom the illumination then sensed and stored for later use. By“determining”, we simply mean noting that an acoustic wave is presentthat is capable of acoustically illuminating the structure. The acousticwave may be deliberately created, either internally or externally to thestructure, for the illumination purposes, or may be created for someother use, such as seismic surveying, its use for acoustic illuminationthen being a secondary beneficial effect. Alternatively, the acousticillumination may be non-determinative, such as naturally, randomly orpseudo-randomly occurring incident noise from some other source.

In one embodiment the method calculates the speed of sound in one ormore parts of the structure or in the fluid from the acoustic data. Assuch, embodiments of the invention may be used for both fluid phasedetermination, as well as structural integrity checking.

In another embodiment the stored or sensed data may be used to determineproperties of fluid flow in the structure from the acoustic data. In onepreferred embodiment the properties include the speed of fluid flow inthe structure. As such, this embodiment may be used for fluid flowmonitoring purpose.

For example, in one embodiment the method uses the stored acoustic datato calculate the speed of sound in the fluid from the acoustic data. Inanother embodiment the stored or sensed data may be used to calculatethe speed of fluid flow in the structure from the acoustic data.

In one embodiment a processor is provided that is arranged to plot theacoustic data as a two dimensional space-time image. The processor thenapplies a two dimensional Fourier transform to the space-time image toobtain a transformed image. Gradients may then be identified in thetransformed image, the identified gradients corresponding to the speedof sound, or at least a property or derivative thereof, of the coupledacoustic energy.

In one embodiment the identified gradients indicate the speed of soundin opposite directions along the flow carrying structure. This allowsthe processor to calculate the fluid flow in dependence on a differencebetween the respective speeds of sound in the fluid in the oppositedirections.

In one embodiment the acoustic wave is generated remote from thestructure, whereas in another embodiment the acoustic wave may begenerated next to or within the structure.

In one embodiment the acoustic wave is generated by a seismic source,wherein preferably the seismic source is a source selected from thegroup comprising: airguns, vibroseis, explosives, or piezo transducers.

In another embodiment the acoustic wave is generated by an internalsource to the structure. In particular the acoustic source may be amechanism driven by the fluid flow.

The acoustic wave may take many forms, and may be for example one of apseudo random sequence or an impulse.

In a preferred embodiment acoustic data is not stored substantiallyduring time periods between the periods when the acoustic wave isincident on and propagating through the structure. This reduces theamount of data that is generated and stored by the DAS.

In one embodiment the generation of the acoustic wave and the sensingand storing of acoustic data are synchronised. In particular, thegeneration of the acoustic wave may be triggered, and then the DAS maywait for any propagation delay until the generated wave is incident onthe structure before sensing the coupled acoustic energy and storingcorresponding acoustic data.

In the above embodiment the DAS preferably ceases the storing ofacoustic data once the acoustic wave has propagated along the structure.

In a particularly preferred embodiment the distributed acoustic sensoris an optical fibre based sensor. Moreover, preferably the structure isa pipe, well, or borehole.

From a further aspect the present invention also provides a system formonitoring a fluid-flow carrying structure, the system comprising anacoustic generator for generating an acoustic wave; and a distributedacoustic sensor for sensing, at the same time as the generated acousticwave is incident on the structure, acoustic energy coupled into thefluid-flow carrying structure from the incident generated acoustic waveand for storing acoustic data corresponding to the sensed acousticenergy.

In another aspect the present invention also provides a fluid-flowcarrying structure comprising an elongate fluid carrying channel throughwhich fluid may flow; and an acoustic transmission mechanism arranged inuse to couple incident acoustic energy into the fluid flow carryingstructure. In this aspect the fluid flow carrying structure may bespecially adapted to allow illuminating acoustic energy incident fromthe outside to be coupled therein, thereby enhancing the acousticillumination effect of the present invention.

In one embodiment the acoustic transmission mechanism comprises a drumstructure having a first surface and a second surface and an acousticconnection mechanism to conduct acoustic energy incident on the firstsurface to the second surface. The first surface is reactive to incidentacoustic waves and vibrates when such waves are incident thereon. Theacoustic vibrations are passed by the acoustic connection mechanism(such as one or more linking arms or the like) to the second surface,which is arranged to radiate the acoustic energy outwards, into thestructure, and thereby couple the energy into the structure.

In another embodiment the acoustic transmission mechanism comprises anacoustic transmission rod extending through at least one part of thestructure for transmitting acoustic energy through the at least onepart. In this case incident acoustic vibrations are passed by the rodinto the structure, and thereby coupled into the structure.

In some embodiments the structure is a pipe, well, or borehole, andparticularly an oil or gas well.

Further features and aspects of the invention will be apparent from theappended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

Further features and advantages of the present invention will becomeapparent from the following description of an embodiment thereof,presented by way of example only, and by reference to the drawings,wherein like reference numerals refer to like parts, and wherein:

FIG. 1 is a diagram illustrating an example DAS deployment of the priorart;

FIG. 2 is a drawing of an example space-time plot of the data collectedby a DAS in a deployment like that of FIG. 1;

FIG. 3 is a drawing of a 2D Fourier transform (kω plot) of thespace-time plot of FIG. 2;

FIG. 4 is a graph showing upwards and downwards speed of sounds in apipe, (top) together with calculated Doppler shifts (bottom) thatprovide fluid velocity measurements;

FIGS. 5 to 7 are drawings of example kω plots taken at different timesin the same well subject to acoustic illumination (which occurs in FIG.6);

FIGS. 8 to 10 are diagrams illustrating how various noise sources may beprovided in embodiments of the invention;

FIG. 11 is a flow diagram illustrating the sequence of operations inembodiments of the invention;

FIG. 12 is a drawing illustrating possible modifications to be made tocasing of a well to allow the well to be more acoustically coupled tothe surroundings;

FIG. 13 is a drawing illustrating one of the modifications of FIG. 12 inmore detail; and

FIG. 14 is a drawing illustrating another of the modifications of FIG.12 in more detail.

DESCRIPTION OF THE EMBODIMENTS

Overview of Embodiments

The success of DAS-based fluid flow measurements depends on the presenceof audio frequency and sub-audio frequency noise within the flow. Quietflows have been seen not to produce useful DAS generated data, such as,for example, k-omega (k-ω) data. Ambient noise from the groundsurrounding boreholes can ‘creep in’ to pipes to illuminate themacoustically, but naturally generated ambient levels are usually muchtoo low to be detectable by a DAS. To solve this problem embodiments ofthe invention combine a sound source in synchronization with monitoringusing a DAS, so that the sound source acoustically illuminates theinterior of the borehole, and allows the DAS to log data that can beused to determine the fluid flow.

Determination of Fluid Flow

FIG. 1 illustrates a typical DAS deployment in an oil well. The well 12extends through rock strata as shown, and a fibre optic cable 14 isprovided running along the length of the well, in this casesubstantially parallel thereto. In other embodiments the cable mayextend along the well in a different manner, for example wrapped aroundelements of the well. In this respect, all that is important is thatthere is a known relationship between the different parts of the cableand the different parts of the well.

The fibre optic cable 14 is connected to a distributed acoustic sensor(DAS), such as the Silixa Ltd iDAS™, referenced previously. The DAS isable to record sound incident on the cable at between 1 m and 5 mresolution along the whole length of the cable, at frequencies up toaround 100 kHz. Hence, monitoring of the well with the DAS results in alarge amount of data, that may be represented by a two dimensionalspace-time plot, an example of which is shown in FIG. 2. Here, thehorizontal axis shows “depth”, or distance along the cable, and the lefthand vertical axis shows time. The right hand vertical axis shows acolour chart, with different colours representing sound of differentintensity. Hence, the 2D space time plot provides a visual record ofwhere on the cable sound was heard, and at what measurement time.

In more detail, the DAS system can measure the phase of the acousticsignal coherently along the fibre optic cable. Therefore, it is possibleto use a variety of methods to identify the presence of propagatingacoustic waves. In one such method, described solely by way ofnon-limiting example, digital signal processing can transform the timeand linear space (along the well) into a diagram showing frequency (ω)and wavenumber (k) in k-ω space. A frequency independent speed of soundpropagation along the well will show up as a line in k-ω space. FIG. 2shows the time and space signal and FIG. 3 shows the corresponding k-ωspace. Using the data in FIG. 3, a good fit for the speed of sound canbe calculated, by determining the gradient of the diagonal lines. Thefrequency band over which the speed of sound can be determined is morethan sufficient for compositional and flow characterization. With theDAS system the speed of sound can be evaluated over a large section ofthe well and, therefore, measure the distributed variations of the flowcomposition and characteristics along the well. The technique isparticularly powerful for determining the composition of the flow—forexample, gas has a speed of sound of around 600 m/s whereas water has aspeed of sounds around 1500 m/s.

Using such k-ω analysis the speed of sound can also be determinedthroughout the entire length of the well. Importantly, each of the twodiagonal lines shown in the k-ω space of FIG. 3 corresponds to the speedof sound either travelling up or down the well. These two lines can beanalysed to reveal the Doppler-shifted sound speeds for upward anddownward propagating sound within the fluid of interest. FIG. 4 showsthe distributed flow determined in a gas injector based on Doppler shiftmeasurements for a 30 s sampling. The determined flow speed varies withdepth in the well corresponding to the change in hydrostatic pressurefor a section of tubing with a uniform inner dimension and a graduallysloped well trajectory. In total the instantaneous and locallydetermined flow is roughly within +/−0.3 m/s (that for this well is 10%)of the actual flow speed. The match to reference measurements is withinthe uncertainties of an instantaneous measurement, the fluid propertyand the distribution of the pressure drop within the well.

In further detail, it is possible to estimate the speed of a given flowby monitoring the speeds of sound within that flow. In this analysis, itis assumed that the flow direction is coincident with the array layout(e.g. the direction of arrival for acoustic signals is known to be 0 or180 degrees). The main principle used is that any sound contained withinthe flow reaches each consecutive sensor with a certain delay. Knowledgeof the spatial sampling (i.e. the distribution of the cable along thewell) can be used to calculate speed of sound by taking the ratio ofaverage inter-sensor time difference of arrival and the average spatialdistance between sensors. This operation can be easily done in thefrequency domain. To perform this operation, in one embodiment oneconstructs a space-time plot of the signal across a neighbourhood ofsensors. The 2D Fourier Transform of information this will give awavenumber-frequency (k-ω) plot.

If the speed of sound is constant across all frequencies (i.e. there isno dispersion) then each frequency (ω) of a signal will correspond to acertain wavenumber (k) on the k-ω plot. Thus ideally a space-time signalwill be mapped into a single straight line on the k-ω plot. From thewave equation we know that kc=w, where c is the speed of sound. Soestimating the slope of the line of highest energy on the k-ω plot willgive us the speed of sound in the medium.

Since the waveguide can sustain propagation both along and against thedirection of flow, the k-ω plot can show two slopes for each mode ofpropagation: one positive and one negative. As the slope of each ofthese lines indicates the sound speed in each direction, the Dopplermethod can be used to derive the speed of sound from the 2D FFTaccording to the well-known method of analysis below.

c+=c+v [speed of sound along the flow]

c−=c−v [speed of sound against the flow]

c+ and c− are found as slopes on a k-ω plot. Combination of the twoequations above gives the flow speed (Ev¹) as v=(c+−c−)/2.

Please note that whilst the above description makes use of processingusing k-ω plots, in other embodiments different processing may beundertaken to achieve the same results, and not all embodiments of theinvention are required to use the k-ω techniques described.

Illumination Using Noise Sources

As noted above, embodiments of the invention are directed at determiningfluid flow of quiet wells, by using an acoustic source to “illuminate”the well and allow the DAS to collect data from which the fluid flow canthen be found. It is therefore necessary to consider the physicalmechanism of how acoustic energy can be coupled into a fluid carryingstructure such as a pipe, well, or borehole.

Waveguides are systems which exhibit a very high propensity to directenergy along particular pathways. Pipes are one-dimensional acousticwaveguides, the acoustic characteristics of which have beenwell-analysed within the classical acoustics literature. As a result ofthese waveguide properties, acoustic sources external to pipes can beused to illuminate acoustically the internal volumes of those pipes evenwhen the source of interest is external to the pipe. In one embodimentof the present invention, a source in the vicinity of the pipe, such asa vibroseis or dropped weight, will drive an acoustic signal into theground. As the signal radiates through the ground and encounters thepipe, acoustic energy will tend to be coupled into the pipe and beredirected along the pipe primary dimension. An acoustic sensor arraymounted within or along the pipe coincident with the pipe principaldimension can be used to interpret the speed of sound within the pipevolume and wall (and, if present, the outer annulus). Regardless of therelative phase of different acoustic waves as they enter the pipe, thespeeds of sound in both the forward and reverse directions ofpropagation can be determined, and hence flow speed can be observed. Oneaspect is that the energy entering the pipe should preferably be belowthe cutoff frequency for the waveguide, else energy will not propagateas a plane wave and wave speed determination will be increased incomplexity.

Potential Noise Sources

Many different noise sources may be used in embodiments of theinvention, as shown in FIGS. 8 to 10. For example, seismic sources suchas seismic source 90 remote from the well, as shown in FIG. 8, or nextto or in the well, as shown in FIG. 9, may be used. 1. Such seismicsources (90, 100) may be airguns, vibroseis, explosives, or piezotransducers either placed outside the well or in the well.

In addition, passive sources powered by the flow, for example a clapperor a spinner 110 with a clicking mechanism attached may be used, asshown in FIG. 10.

Additionally, in further embodiments active sources powered by powerharvesting techniques may be used. An example is that the flow orvibrations in the well may be used to generate power which is then usedto power a device (for example a pulsing piezo).

In further embodiments pump noise may be used, or, for offshore wells,the noise from boats or ships located near the base well or pipe may beused. In addition, pressure waves from opening and closing valves withina well or pipe may be used, in that the opening and closing, ifperformed suddenly enough, can generate an acoustic pressure wave thattravels along a pipe or well of which the valves form a part.

Moreover, in some embodiments acoustic sources can distributed along thewell, borehole, or pipe. For example, the distribution may be regular,in that the sources are evenly spaced along sections of the well,borehole, or pipe, or the distribution may follow a mathematicalfunction. For example, the distribution might be logarithmically spacedalong one or more sections of a pipe. In other embodiments, acousticsources might be randomly or pseudo-randomly spaced along the pipe.Moreover, in further embodiments different sections of pipe may have adifferent distribution of acoustic sources therein.

With respect to the precise noise signal that may be used, the use ofrandom or pseudo-random vibroseis-generated signals in a zero-offsetarrangement tandem with a flowing well monitored by a DAS should allowfor sufficient averaging to yield useful flow data even in nearly silentwells. Noise generated within wells could also be used for this type ofillumination.

In practice, this would involve bringing a vibroseis up to a well, anddriving it with a pseudo-random signal for a while (maybe a few minutes)while the DAS acquires data. This could also be done with otherexcitations (single pulses, chirps) but pseudo-random is practically andtheoretically the most robust method.

Method of Operation

FIG. 11 illustrates the overall operation of the embodiments in FIGS. 8to 10. At step 12.2 the acoustic illuminator (i.e. the sound source,whether seismic or otherwise) is operated. If the sound source is some(known) distance away then it is necessary to wait for the illuminationacoustic wave to propagate to the site of the well, pipe, or borehole,as shown at step 12.4. However, if the sound source is local, then it isnot necessary to wait for this propagation period.

At the same time as (or just before) the acoustic wave is incident onthe well, pipe, or borehole, the DAS system 10 is activated to beginlogging space-time acoustic data, at step 12.6. Thus, the DAS begins torecord acoustic data representative of the incident acoustic wave beingcoupled into the fluid carrying structure. Once the acoustic energy hasbeen coupled into the structure and propagated there along, the datalogging can then stop. Hence, it becomes necessary to log data for onlya short period of time during the actual illumination by the acousticsource.

Once the space time data has been obtained, at steps 12.8 and 12.10 thesame steps as described above to calculate the speed of sound in theflowing medium, and then the actual flow speed itself are performed.These steps may be performed substantially in real time immediatelyafter the data has been captured, or as a post-processing step some timelater.

One benefit to using active acoustic illumination in fluid flow meteringin boreholes is the ability to synchronize the flow measurement with theacoustic source firing. This can greatly increase the signal to noiseratio of results by allowing averaging to be calculated using only dataknown to contain useful acoustic signal. Quiet periods outside of thetime when an acoustic illumination signal is present are not recordedand hence do not contribute to the averaged signal. This method alsoallows for a significant reduction in the amount of data that needs tobe collected since the period of acoustic illumination represents only afraction of the recording time when compared to continuous data logging.

For this to be done effectively it is necessary to synchronize theacoustic source generation with the recording made by the DAS. Inembodiments of the invention this can be done in two ways. The firstmethod uses an accurately timed trigger signal to initiate the acousticsource and the DAS data recording at the same time. Depending on theposition of the acoustic source used to provide the illuminationrelative to the borehole, delays can be built into the recording starttime to allow for the travel time of the acoustic waves to the boreholeor a specific region of the borehole. For each source firing a shortrecording is made and the flow speed calculated, in between sourcefirings data does not need to be collected. The second method fires thesource at regular intervals synchronized to an accurate clock signalsuch as GPS time. The DAS, which must also be synchronized to the sameclock, records at the same intervals or offset by a certain amount oftime to allow for travel time of the acoustic illumination source signal

Results

Example results provided by an embodiment of the invention are shown inFIGS. 5 to 7, which show k-ω plots for a number of discrete times duringan experiment. In this experiment, an otherwise quiet pipe with fluidflowing therein pipe was struck with a hammer to provide an acousticimpulse. When k-ω plots are made in the absence of any acousticillumination (as shown in FIGS. 5, and 7), the speed of sound cannot beseen. However, when k-ω plots are made during time periods coincidentwith the impulse (corresponding to FIG. 6), the speeds of soundcorresponding to the various media within the pipe cross-section can beseen. As described above, these speeds of sound can be used to derive(1) the flow speed (2) information concerning the nature of the fluidand (3) well integrity data.

As noted, FIGS. 5 to 7 show k-ω results are shown for a cement-linedpipe with a dense acoustic sensor array embedded within the array.

FIG. Time Number period Condition Summary of kω plot 5   0 s-0.15Silence No speeds visible 6 0.20 s-0.35 s Impulse Waveguidecharacteristics introduced by including fluid sound hammer on speedclearly visible pipe exterior 7 0.40 s-0.55 s Silence No speeds visible

In summary, therefore, embodiments of the present invention provide forthe deliberate incidence of an actively generated acoustic wave onto afluid flow carrying structure simultaneous with data logging beingundertaken by a DAS that monitors the structure. The incident acousticenergy couples into the fluid flow carrying structure and effectivelyacoustically propagates along the fluid, allowing speed of sound in thefluid to be determined, from which fluid flow speed can then bedetermined. Many different sound sources either within or without thefluid flow carrying structure may be used, such as seismic sources, orflow driven devices.

A further aspect of the present invention relates to the adaptation ofthe fluid flow carrying structure itself so as to enhance its ability tocouple into its interior acoustic energy incident from the outside. Inthis respect external acoustic illumination of the interior of thestructure can be enhanced by coupling into the structure more of theincident energy. Thus, for example, in the case of an oil or gas wellthe outer casing of the well may be adapted by the provision of anacoustic coupling mechanism arranged to couple into the interior of thewell acoustic energy incident externally. FIGS. 12 to 14 illustratespecific examples.

As shown in FIG. 12, the outer casing of a well 12 may be provided withdevices or other adaptations to improve the ability of the well tocouple into its interior incident acoustic energy, that then travelsalong the well in waveguide mode, as described previously. Inparticular, one such mechanism is a drum type arrangement 132 whichpasses from the outside of the well through the outer cement and casing,into the interior, and which operates similar to an ear drum to transmitacoustic energy. FIG. 13 illustrates the arrangement in further detail.

More specifically, in FIG. 13 an acoustic transmission drum 132 isshown, wherein the drum extends in this case through (in order fromoutside in the direction inwards) the cement, casing, annulus, andtubing into the interior of the well. In other embodiments the drum mayonly extend through a subset of these layers, for example, may extendthrough the cement or casing into, but not through, the annulus, orthrough the tubing and annulus from the casing. In further embodimentsindividual drums 132 may be provided in the respective layers, or asubset of the layers of the well. For example, the tubing layer may beprovided with a respective drum that passes therethrough, and the casinglayer may be provided with a respective drum that passes therethrough.Others of the layers may also be provided with their own respectivedrums. In some embodiments, where one or more drums per layer areprovided, the drums may preferably be in spatial alignment from layer tolayer, such that acoustic energy may be passed from drum to drum.

An acoustic transmission drum 132 is shown in more detail in FIG. 13.The drum includes a first acoustically reactive surface 142, such as amembrane or the like, which is sensitive to incoming acoustic vibrationssuch that the vibrations are transferred into the membrane. A secondacoustically reactive surface 144, which may also be a membrane, ismechanically coupled to the first surface such that any acousticvibrations induced in the first surface are transferred to the secondsurface. In this respect, the mechanical coupling 146 may be arranged toamplify the acoustic vibrations transferred to the second surface, forexample by using a linked arm arrangement with a pivot point arranged toprovide a mechanical advantage. In particular, as shown in FIG. 13, afirst arm attached at one end to the first surface 142 is pivotallyattached to a linking arm. The linking arm is pivotally mounted about afixed pivot point, and is pivotally attached at its other end to one endof a second arm. The second arm is attached at its other end to thesecond surface 144. The position of the fixed pivot can be set such thatthe acoustic vibrations transferred from first surface to the secondsurface are increased or decreased in amplitude.

Other transfer mechanisms may be used. For example, a straight-armlinkage (i.e. without the pivots) may be made between the two surfaces,so that vibrations in the first surface are directly transferred to thesecond surface. Such a linkage may simply comprise a connecting rodconnecting the inner surfaces of the two surfaces.

In the embodiment of FIG. 13, the outer face of second surface 144 islocated within the main body of the well, in direct contact with anyfluid flowing therethrough. Therefore, acoustic vibrations can betransferred directly into the fluid, to then propagate up and down thefluid carrying structure, as described previously, and as shown.

The operation of the arrangement is as follows. External acousticvibrations incident on the first surface are transferred to the firstsurface, and then, via the linkage mechanism, to the second surface. Theacoustic vibration of the second surface is then coupled into the fluidin the structure, and propagates up and down the structure as if thestructure were a waveguide, as described previously.

A second acoustic coupling mechanism is shown in FIGS. 12 and 14. Thismechanism comprises rods 134 which extend from the casing through thecement layer and into the surrounding rock strata. On FIG. 12 the rodsare not shown to scale, and as an example may be a few (2-3) to several(20-30) centimetres in length, although other lengths may be used. Asshown in FIG. 14, the rods are coupled through the cement, casing,annulus and tubing into the well interior, and are provided on theirinner ends with vibration surfaces 152 to transmit any acousticvibrations in the rods into the fluid in the well. The rods may befirmly mounted such that they cannot move, or alternatively may beslightly sprung mounted (not shown), such that they are able to move inand out in their elongate direction, as shown in FIG. 14.

The operation of the arrangement of FIG. 14 is as follows. Externalacoustic vibrations in the surrounding rock strata and incident on therods are transferred to the through the rods into the interior of thestructure, and via the vibration surfaces into the fluid flowingtherethrough. The acoustic vibration of vibration surfaces is coupledinto the fluid in the structure, and propagates up and down thestructure as if the structure were a waveguide, as described previously.

In variations of the embodiment of FIG. 14, the rods may only extendthrough some of the outer layers, such as the cement layer and thecasing for example, but not through all of the outer layers.

In the above embodiments focus has been made on coupling acousticillumination energy into the fluid in a structure so as to illuminatethe fluid and allow fluid flow to be found. However, in furtherembodiments the acoustic illumination energy may be intentionallycoupled into the structure itself, to allow speed of sound in thestructure to be determined to allow for structure integrity checking.For example, in the case of an oil well acoustic energy may be coupledinto the cement layer and detected propagating through the cement layerto determine cracks or discontinuities in the cement layer. In thisrespect, the cement layer may be provided with an acoustic couplingmechanism such as those described above, which ends within the cementlayer, and goes no further into the structure. For example a rod 134 ordrum 132 may be provided extending from outside the well into the cementlayer, but no other layer. This would act to couple incident acousticenergy from the outside primarily into the cement layer. Whilst some ofthe energy would also likely couple into other parts of the structure,the DAS should be able to resolve the acoustic energy travelling throughthe cement layer, and hence be able to check the structural integritythereof.

Similar arrangements could also be made to check the integrity of otherlayers using external acoustic illumination.

In the above embodiments we have focussed on fluid flow carryingstructures. In other embodiments, any other structure may be monitored,for example for structural integrity, using the acoustic illuminationand DAS sensing techniques described. The invention is therefore notlimited to the monitoring of fluid flow carrying structures, and extendsto a method and system for monitoring a structure, comprisingdetermining the generation of an acoustic wave; and at the same time asthe generated acoustic wave is incident on the structure, sensing, usinga distributed acoustic sensor, acoustic energy coupled into thestructure from the incident generated acoustic wave.

Various modifications may be made to the above described embodiments toprovide further embodiments, any and all of which are intended to beencompassed by the appended claims.

What is claimed is:
 1. A method of monitoring a fluid-flow carryingstructure, the method comprising: determining a generation of anacoustic wave; at the same time as the generated acoustic wave isincident on the fluid-flow carrying structure, sensing, using an opticalfiber distributed acoustic sensor, acoustic energy coupled into thefluid-flow carrying structure from the incident generated acoustic wave,wherein the acoustic energy coupled into the fluid-flow carryingstructure has a frequency below a cutoff frequency of the fluid-flowcarrying structure; and storing acoustic data corresponding to thesensed acoustic energy; wherein the generation of the acoustic wave, thesensing of the acoustic energy and the storing of acoustic data aresynchronised such that, upon the generation of an acoustic wave, thesensing of the acoustic energy and the storing of the acoustic data areactivated when the generated acoustic wave is incident on the fluid-flowcarrying structure and deactivated once the generated acoustic wave haspropagated along the fluid-flow carrying structure.
 2. A methodaccording to claim 1, wherein the acoustic wave is generated remote fromthe structure, or next to or within the structure.
 3. A method accordingto claim 1, wherein the acoustic wave is generated by a seismic source,the seismic source being a source selected from the group comprising:airguns, vibroseis, explosives, or piezo transducers.
 4. A methodaccording to claim 1, wherein the acoustic wave is generated by anacoustic source internal to the structure.
 5. A method according toclaim 4, wherein the acoustic source is a mechanism driven by a fluidflow.
 6. A method according to claim 1, wherein the acoustic wave is oneof a pseudo random sequence or an impulse.
 7. A method according toclaim 1, wherein the method further comprises: triggering the generationof the acoustic wave; waiting for any propagation delay until thegenerated acoustic wave is incident on the structure; and then sensingthe coupled acoustic energy and storing the corresponding acoustic data.8. A method according to claim 7, and further comprising ceasing thestoring of acoustic data once the acoustic wave has propagated along thestructure.
 9. A method according to claim 1, wherein the structure is apipe, well, or borehole.
 10. A system for monitoring a fluid-flowcarrying structure, the system comprising: an acoustic wave generatorfor generating an acoustic wave; and an optical fiber distributedacoustic sensor (DAS) for sensing, at the same time as the generatedacoustic wave is incident on the fluid-flow carrying structure, acousticenergy coupled into the fluid-flow carrying structure from the incidentgenerated acoustic wave and for storing acoustic data corresponding tothe sensed acoustic energy, wherein the acoustic energy coupled into thefluid-flow carrying structure has a frequency below a cutoff frequencyof the fluid-flow carrying structure; wherein the acoustic wavegenerator and the DAS are synchronised such that, upon the generation ofan acoustic wave, the sensing of the acoustic energy and the storing ofthe acoustic data are activated when the generated acoustic wave isincident on the fluid-flow carrying structure and deactivated once thegenerated acoustic wave has propagated along the fluid-flow carrying.11. A system according to claim 10, wherein the DAS is further arrangedto: wait for any propagation delay from a triggering of the generationof the acoustic wave until the generated wave is incident on thestructure; and then sense the coupled acoustic energy and storecorresponding acoustic data.
 12. A system according to claim 11, whereinthe DAS is further arranged to cease the storing of the acoustic dataonce the acoustic wave has propagated along the structure.